Wellbores are formed in subterranean formations for various purposes including, for example, extraction of oil and gas from the subterranean formation and extraction of geothermal heat from the subterranean formation. Sensors are employed to monitor conditions at downhole locations in the wellbores, either during drilling or after drilling. Examples of downhole characteristics that may be monitored using sensors include temperature, pressure, fluid flow rate and type, formation resistivity, cross-well and acoustic seismometry, perforation depth, fluid characteristics or logging data.
Sensors utilized at a drilling site may be incorporated within a drill string. A “drill string,” as it is referred to in the art, comprises a series of elongated tubular segments connected end-to-end, and extends into the wellbore from a drilling rig or platform. An earth-boring rotary drill bit and other components may be coupled at the distal end of the drill string at the bottom of the wellbore being drilled. This assembly of tools and components is referred to in the art as a “bottom hole assembly” (BHA). Wirelines can also be used in a wellbore as part of drilling operations or during post-drilling operations. A “wireline” or “slickline,” both terms used in the art, comprises a long wire, cable, or coil tubing often used to lower or raise downhole tools used in oil and gas well maintenance to the appropriate depth of the drilled well. Sensors may be incorporated within such wirelines.
Of the sensors utilized in drilling systems, acoustic sensors are common. In known systems, an acoustic sensor, typically with a piezo-ceramic transducer on board, operates in a pulse-echo mode in which it is utilized to both send and receive a pressure pulse in drilling fluid (also referred to as drilling mud). In such systems, the transmitter and receiver of the acoustic sensor are integrated together. In other known systems, an acoustic sensor includes an acoustic receiver configured to detect a signal resulting from a signal transmitted by a separate acoustic transmitter. In such systems, the acoustic sensor transmitter may be located nearby the acoustic sensor receiver or arrayed down the length of the downhole tool from the receiver incorporated within the tool. In use, an electrical drive voltage (e.g., a square wave pulse) is applied to the transducer of the acoustic sensor transmitter, which vibrates the surface of the transducer of the transmitter and launches a pressure pulse into the drilling fluid. A portion of the ultrasonic energy is typically reflected at the drilling fluid/borehole wall interface and is received by the transducer of the acoustic sensor receiver, which induces an electrical response therein. In systems having an acoustic sensor with an integrated receiver and transmitter, the transducer launching the pressure pulse may be the transducer that also receives the response. Various characteristics of the downhole environment may be inferred from the received signal, such as the borehole diameter, measure eccentricity, and drilling-fluid properties.
Conditions in a downhole environment are often harsh. Sensors used downhole must typically withstand temperatures ranging to and beyond 150 degrees Celsius and pressures ranging up to about 30,000 psi. Surrounded by earth, debris, and drilling mud, downhole conditions are often also moisture-filled spaces, yet, sensors may have sensitive components that can be damaged when coming into contact with water. For example, in an acoustic sensor employing a piezoelectric ceramic transducer, exposure of the ceramic material to moisture at high pressures and temperatures makes the ceramic transducer vulnerable to water diffusion therein, which may alter the capacitance and the dielectric constant of the ceramic material. Such alterations compromise the sensor's ability to detect signals accurately.
Attempts have been made to reduce the likelihood of exposure of the sensitive components of sensors to potentially damaging conditions. Such attempts include surrounding the sensitive components of the sensor with a material, such as silicone oil. Examples of such use of protective surrounds are disclosed in, for example, U.S. Pat. No. 7,036,363, which issued May 2, 2006, to Yogeswaren; U.S. Pat. No. 7,075,215, which issued Jul. 11, 2006, to Yogeswaren; U.S. Pat. No. 7,180,828, which issued Feb. 20, 2007, to Sommer et al.; and U.S. Pat. No. 7,825,568, which issued Nov. 2, 2010, to Andle.